DISTURBANCE ANALYSIS FOR POWER SYSTEMS

DISTURBANCE ANALYSIS FOR POWER SYSTEMS

DISTURBANCE ANALYSIS FOR POWER SYSTEMS Mohamed A. Ibrahim New York Power Authority Director of Protection and Control (Retired)

Copyright Ó 2012 by Mohamed A. Ibrahim. All rights reserved Published by John Wiley & Sons, Inc., Hoboken, New Jersey Published simultaneously in Canada No part of this publication may be reproduced, stored in a retrieval system, or transmitted in any form or by any means, electronic, mechanical, photocopying, recording, scanning, or otherwise, except as permitted under Section 107 or 108 of the 1976 United States Copyright Act, without either the prior written permission of the Publisher, or authorization through payment of the appropriate per-copy fee to the Copyright Clearance Center, Inc., 222 Rosewood Drive, Danvers, MA 01923, (978) 750-8400, fax (978) 750-4470, or on the web at www.copyright.com. Requests to the Publisher for permission should be addressed to the Permissions Department, John Wiley & Sons, Inc., 111 River Street, Hoboken, NJ 07030, (201) 748-6011, fax (201) 748-6008, or online at http://www.wiley.com/go/permission. Limit of Liability/Disclaimer of Warranty: While the publisher and author have used their best efforts in preparing this book, they make no representations or warranties with respect to the accuracy or completeness of the contents of this book and specifically disclaim any implied warranties of merchantability or fitness for a particular purpose. No warranty may be created or extended by sales representatives or written sales materials. The advice and strategies contained herein may not be suitable for your situation. You should consult with a professional where appropriate. Neither the publisher nor author shall be liable for any loss of profit or any other commercial damages, including but not limited to special, incidental, consequential, or other damages. For general information on our other products and services or for technical support, please contact our Customer Care Department within the United States at (800) 762-2974, outside the United States at (317) 572-3993 or fax (317) 572-4002. Wiley also publishes its books in a variety of electronic formats. Some content that appears in print may not be available in electronic formats. For more information about Wiley products, visit our web site at www.wiley.com. Library of Congress Cataloging-in-Publication Data: Ibrahim, Mohamed A., 1943- Disturbance analysis for power systems / Mohamed A. Ibrahim. p. cm. Includes index. ISBN 978-0-470-91681-0 (cloth) 1. Electric power system stability. 2. Transients (Electricity) 3. Electric power failures. 4. Electric network analysis. I. Title. TK1010.I27 2011 621.319 dc22 2010048274 Printed in the United States of America epdf ISBN: 978-1-118-17211-7 obook ISBN: 978-1-118-17209-4 epub ISBN: 978-1-118-17210-0 10 9 8 7 6 5 4 3 2 1

To my mother, who taught me without knowing how to read or write; my father; my wife; and my family

CONTENTS Preface xvii 1 POWER SYSTEM DISTURBANCE ANALYSIS FUNCTION 1 1.1 Analysis Function of Power System Disturbances 2 1.2 Objective of DFR Disturbance Analysis 4 1.3 Determination of Power System Equipment Health Through System Disturbance Analysis 5 1.4 Description of DFR Equipment 6 1.5 Information Required for the Analysis of System Disturbances 7 1.6 Signals to be Monitored by a Fault Recorder 8 1.7 DFR Trigger Settings of Monitored Voltages and Currents 10 1.8 DFR and Numerical Relay Sampling Rate and Frequency Response 11 1.9 Oscillography Fault Records Generated by Numerical Relaying 11 1.10 Integration and Coordination of Data Collected from Intelligent Electronic Devices 12 1.11 DFR Software Analysis Packages 12 1.12 Verification of DFR Accuracy in Monitoring Substation Ground Currents 21 1.13 Using DFR Records to Validate Power System Short-Circuit Study Models 24 1.14 COMTRADE Standard 31 2 PHENOMENA RELATED TO SYSTEM FAULTS AND THE PROCESS OF CLEARING FAULTS FROM A POWER SYSTEM 33 2.1 Shunt Fault Types Occurring in a Power System 33 2.2 Classification of Shunt Faults 34 2.3 Types of Series Unbalance in a Power System 39 2.4 Causes of Disturbance in a Power System 39 vii

viii CONTENTS 2.5 Fault Incident Point 40 2.6 Symmetric and Asymmetric Fault Currents 41 2.7 Arc-Over or Flashover at the Voltage Peak 44 2.8 Evolving Faults 48 2.9 Simultaneous Faults 51 2.10 Solid or Bolted (R F ¼ 0) Close-in Phase-to-Ground Faults 52 2.11 Sequential Clearing Leading to a Stub Fault that Shows a Solid (R F ¼ 0) Remote Line-to-Ground Fault 53 2.12 Sequential Clearing Leading to a Stub Fault that Shows a Resistive Remote Line-to-Ground Fault 54 2.13 High-Resistance Tree Line-to-Ground Faults 56 2.14 High-Resistance Line-to-Ground Fault Confirming the Resistive Nature of the Fault Impedance When Fed from One Side Only (Stub) 58 2.15 Phase-to-Ground Faults on an Ungrounded System 59 2.16 Current in Unfaulted Phases During Line-to-Ground Faults 60 2.17 Line-to-Ground Fault on the Grounded-Wye (GY) Side of a Delta/GY Transformer 63 2.18 Line-to-Line Fault on the Grounded-Wye Side of a Delta/GY Transformer 65 2.19 Line-to-Line Fault on the Delta Side of a Delta/GY Transformer with No Source Connected to the Delta Winding 66 2.20 Subcycle Relay Operating Time During an EHV Double-Phase-to-Ground Fault 68 2.21 Self-Clearing of a C-g Fault Inside an Oil Circuit Breaker Tank 69 2.22 Self-Clearing of a B-g Fault Caused by a Line Insulator Flashover 70 2.23 Delayed Clearing of a Pilot Scheme Due to a Delayed Communication Signal 71 2.24 Sequential Clearing of a Line-to-Ground Fault 72 2.25 Step-Distance Clearing of an L-g Fault 74 2.26 Ground Fault Clearing in Steps by an Instantaneous Ground Element at One End and a Ground Time Overcurrent Element at the Other End 76 2.27 Ground Fault Clearing by Remote Backup Following the Failures of Both Primary and Local Backup (Breaker Failure) Protection Systems 78 2.28 Breaker Failure Clearing of a Line-to-Ground Fault 79 2.29 Determination of the Fault Incident Point and Classification of Faults Using a Comparison Method 81

CONTENTS ix 3 POWER SYSTEM PHENOMENA AND THEIR IMPACT ON RELAY SYSTEM PERFORMANCE 85 3.1 Power System Oscillations Leading to Simultaneous Tripping of Both Ends of a Transmission Line and the Tripping of One End Only on an Adjacent Line 86 3.2 Generator Oscillations Triggered by a Combination of L-g Fault, Loss of Generation, and Undesired Tripping of Three 138-kV Lines 91 3.3 Stable Power Swing Generated During Successful Synchronization of a 200-MW Unit 95 3.4 Major System Disturbance Leading to Different Oscillations for Different Transmission Lines Emanating from the Same Substation 96 3.5 Appearance of 120-Hz Current at a Generator Rotor During a High-Side Phase-to-Ground Fault 98 3.6 Generator Negative-Sequence Current Flow During Unbalanced Faults 101 3.7 Inadvertent (Accidental) Energization of a 170-MW Hydro Generating Unit 102 3.8 Appearance of Third-Harmonic Voltage at Generator Neutral 104 3.9 Variations of Generator Neutral Third-Harmonic Voltage Magnitude During System Faults 106 3.10 Generator Active and Reactive Power Outputs During a GSU High-Side L-g Fault 107 3.11 Loss of Excitation of a 200-MW Unit 108 3.12 Generator Trapped (Decayed) Energy 110 3.13 Nonzero Current Crossing During Faults and Mis-Synchronization Events 112 3.14 Generator Neutral Zero-Sequence Voltage Coupling Through Step-Up Transformer Interwinding Capacitance During a High-Side Ground Fault 113 3.15 Energizing a Transformer with a Fault on the High Side within the Differential Zone 115 3.16 Transformer Inrush Currents 118 3.17 Inrush Currents During Energization of the Grounded-Wye Side of a YG/Delta Transformer 120 3.18 Inrush Currents During Energization of a Transformer Delta Side 121

x CONTENTS 3.19 Two-Phase Energization of an Autotransformer with a Delta Winding Tertiary During a Simultaneous L-g Fault and an Open Phase 124 3.20 Phase Shift of 30 Across the Delta/Wye Transformer Banks 127 3.21 Zero-Sequence Current Contribution from a Remote Two-Winding Delta/YG Transformer 128 3.22 Conventional Power-Regulating Transformer Core Type Acting as a Zero-Sequence Source 129 3.23 Circuit Breaker Re-Strikes 130 3.24 Circuit Breaker Pole Disagreement During a Closing Operation 132 3.25 Circuit Breaker Opening Resistors 133 3.26 Secondary Current Backfeeding to Breaker Failure Fault Detectors 134 3.27 Magnetic Flux Cancellation 136 3.28 Current Transformer Saturation 138 3.29 Current Transformer Saturation During an Out-of-Step System Condition Initiated by Mis-Synchronization of a Generator Breaker 141 3.30 Capacitive Voltage Transformer Transient 143 3.31 Bushing Potential Device Transient During Deenergization of an EHV Line 144 3.32 Capacitor Bank Breaker Re-Strike Following Interruption of a Capacitor Normal Current 146 3.33 Capacitor Bank Closing Transient 147 3.34 Shunt Capacitor Bank Outrush into Close-in System Faults 149 3.35 SCADA Closing into a Three-Phase Fault 153 3.36 Automatic Reclosing into a Permanent Line-to-Ground Fault 154 3.37 Successful High-Speed Reclosing Following a Line-to-Ground Fault 155 3.38 Zero-Sequence Mutual Coupling Induced Voltage 156 3.39 Mutual Coupling Phenomenon Causing False Tripping of a High-Impedance Bus Differential Relay During a Line Phase-to-Ground Fault 159 3.40 Appearance of Nonsinusoidal Neutral Current During the Clearing of Three-Phase Faults 162 3.41 Current Reversal on Parallel Lines During Faults 164 3.42 Ferranti Voltage Rise 166 3.43 Voltage Oscillation on EHV Lines Having Shunt Reactors at their Ends 168

CONTENTS xi 3.44 Lightning Strike on an Adjacent Line Followed by a C-g Fault Caused by a Separate Lightning Strike on the Monitored Line 172 3.45 Spill Over of a 345-kV Surge Arrester Used to Protect a Cable Connection, Prior to its Failure 173 3.46 Scale Saturation of an A/D Converter Caused by a Calibration Setting Error 174 3.47 Appearance of Subsidence Current at the Instant of Fault Interruption 176 3.48 Energizing of a Medium Voltage Motor that has an Incorrect Formation of the Stator Winding Neutral 177 3.49 Phase Angle Change from Loading Condition to Fault Condition 179 4 CASE STUDIES RELATED TO GENERATOR SYSTEM DISTURBANCES 183 4.1 Generator Protection Basics 184 Case Studies 186 Case Study 4.1 Appearance of Double-Frequency (120-Hz) Current in a Hydrogenerator Rotor Due to Stator Negative-Sequence Current Flow During a 115-kV Phase-to-Ground Fault 186 Case Study 4.2 Inadvertent (Accidental) Energization of a 170-MW Hydro Unit 193 Case Study 4.3 Loss of Excitation for a 200-MW Generating Unit Caused by Human Error 204 Case Study 4.4 Loss-of-Excitation Trip in an 1100-MW Unit 212 Case Study 4.5 Mis-synchronization of a 50-MW Steam Unit for a Combined-Cycle Plant 214 Case Study 4.6 Mis-synchronization of a 200-MW Hydro Unit 222 Case Study 4.7 Undesired Tripping of a Numerical Differential Relay During Manual Synchronization of a Hydro Unit 231 Case Study 4.8 Tripping of a 500-MW Combined-Cycle Plant Triggered by a High-Side 138-kV Phase-to-Ground Fault 236 Case Study 4.9 Tripping of a 110-MW Combustion Turbine Unit in a Combined-Cycle Plant During a Power Swing 244 Case Study 4.10 Analysis of an 800-MW Generating Plant DFR Record for a Normally Cleared 345-kV Phase-to-Ground Fault 247

xii CONTENTS Case Study 4.11 Tripping of a 150-MW Combined-Cycle Plant Due to a Failed Lead of One Generator Terminal Surge Capacitor 250 Case Study 4.12 Generator Stator Ground Fault in an 800-MW Fossil Unit 260 Case Study 4.13 Three-Phase Fault at the Terminal of an 800-MW Generator Unit 265 Case Study 4.14 Three-Phase Fault at the Terminal of a 50-MW Generator Due to a Cable Connection Failure 271 Case Study 4.15 Generator Stator Phase-to-Phase-to-Ground Fault Caused by Failure of the Rotor Fan Blade 276 Case Study 4.16 Undesired Tripping of a Pump Storage Plant During a Close-in Phase-to-Ground 345-kV Line Fault 286 Case Study 4.17 Tripping of an 800-MW Plant and the Associated EHV Lines During a 345-kV Bus Fault 293 Case Study 4.18 Tripping of a 150-MW Combined-Cycle Plant During an External 138-kV Three-Phase Fault 296 Case Study 4.19 Tripping of a 150-MW Combined-Cycle Plant During a Disturbance in the 138-kV Transmission System 303 Case Study 4.20 Undesired Tripping of a 150-MW Combined-Cycle Plant Following Successful Clearing of a 138-kV Double-Phase-to-Ground Fault 308 Case Study 4.21 Undesired Tripping of an Induction Generator by a Differential Relay Having a Capacitor Bank Within the Protection Zone 311 Case Study 4.22 Undesired Tripping of a Steam Unit Upon Its First Synchronization to the System During the Commissioning Phase of a Combined-Cycle Plant 314 Case Study 4.23 Sequential Shutdown of a Steam-Driven Generating Unit as Part of a 500-MW Combined-Cycle Plant 318 Case Study 4.24 Wiring Errors Leading to Undesired Generator Numerical Differential Relay Operation During the Commissioning Phase of a New Unit 320 Case Study 4.25 Phasing a New Generator into the System Prior to Commissioning 324 Case Study 4.26 Third-Harmonic Undervoltage Element Setting Procedure for 100% Stator Ground Fault Protection 327 Case Study 4.27 Basis for Setting the Generator Relaying Elements to Provide System Backup Protection 330 5 CASE STUDIES RELATED TO TRANSFORMER SYSTEM DISTURBANCES 335 5.1 Transformer Basics 336 5.2 Transformer Differential Protection Basics 344

CONTENTS xiii 5.3 Case Studies 347 Case Study 5.1 Energization of a 5-MVA 13.8/4.16-kV Station Service Transformer with a 13.8-kV Phase-to-Phase Bus Fault Within the Transformer Differential Protection Zone 347 Case Study 5.2 Lack of Protection Redundancy for a Generator Step-up Transformer Leads to Interruption of a 230-kV Area 353 Case Study 5.3 Undesired Operation of a Numerical Transformer Differential Relay Due to a Relay Setting Error in the Winding Configuration 357 Case Study 5.4 Location of a 13.8-kV Switchgear Phase-to-Phase Fault Using Transformer Differential Numerical Relay Fault Records 363 Case Study 5.5 Operation of a Unit Step-Up Transformer with an Open Phase on the 13.8-kV Delta Winding 370 Case Study 5.6 Using a Transformer Phasing Diagram, Digital Fault Recorder Record, and Relay Targets to Confirm the Damaged Phase of a Unit Auxiliary Transformer Failure 375 Case Study 5.7 Failure of a 450-MVA 345/138/13.2-kV Autotransformer 381 Case Study 5.8 Failure of a 750-kVA 13.8/0.480-kV Station Service Transformer Due to a Possible Ferroresonance Condition 387 Case Study 5.9 Undesired Tripping of a Numerical Transformer Differential Relay During an External Line-to-Ground Fault 394 Case Study 5.10 Undesired Operation of Numerical Transformer Differential Relays During Energization of Two 75-MVA 138/13.8-kV GSU Transformers 407 Case Study 5.11 Undesired Operation of a Numerical Transformer Differential Relay During Energization of a 5-MVA 13.8/4.16-kV Station Service Transformer 411 Case Study 5.12 Phase-to-Phase Fault Evolving into a Three-Phase Fault at the High Side of a 5-MVA 13.8/4.16-kV Station Service Transformer 414 Case Study 5.13 Phase-to-Phase Fault Evolving into a Three-Phase Fault at the 13.8-kV Bus Connection of a 2-MVA 13.8/0.480-kV Station Service Enclosure 420 Case Study 5.14 Phase-to-Phase Fault in a 13.8-kV Switchgear Caused by Heavy Rain Evolving into a Three-Phase Fault 426 Case Study 5.15 Undesired Operation of a Numerical Transformer Differential Relay Due to a Missing CT Cable Connection as an Input to the Relay Wiring 430 Case Study 5.16 Phase-to-Ground Fault Caused by Flashover of a Transformer 115-kV Bushing Due to a Bird Droppings 434

xiv CONTENTS Case Study 5.17 Using a Transformer Numerical Relay Oscillography Record to Analyze Phase-to-Ground Faults in a 4.16-kV Low-Resistance Grounding Supply 439 Case Study 5.18 Phase-to-Phase Fault Caused by a Squirrel in a 13.8-kV Cable Bus Which Evolves into a Three-Phase Fault 447 Case Study 5.19 13.8-kV Transformer Lead Phase-to-Phase Fault Due to Animal Contact, Evolving into a 115-kV Transformer Bushing Fault 451 Case Study 5.20 Undesired Tripping of a Numerical Multifunction Transformer Relay by Assertion of a Digital Input Wired to the Buchholz Relay Trip Output 456 6 CASE STUDIES RELATED TO OVERHEAD TRANSMISSION-LINE SYSTEM DISTURBANCES 461 6.1 Line Protection Basics 463 6.2 Case Studies 466 Case Study 6.1 Using a DFR Record From One End Only to Determine Local and Remote-End Clearing Times for a Line-to-Ground Fault 466 Case Study 6.2 Analysis of Clearing Times for a Phase-to-Ground Fault from Both Ends of a 345-kV Transmission Line Using Oscillograms from One End Only 469 Case Study 6.3 Analysis of a Three-Phase Fault Caused by Lightning 471 Case Study 6.4 Analysis of a Double-Phase-to-Ground 765-kV Fault Caused by Lightning 473 Case Study 6.5 Assessment of Transmission Tower Footing Resistance by Analyzing a Three-Phase-to-Ground Fault Caused by Lightning 476 Case Study 6.6 115-kV Phase-to-Ground Fault Cleared First from a Solidly Grounded System, Then Connected and Cleared from an Ungrounded System 478 Case Study 6.7 345-kV Phase-to-Ground Fault (C-g) Caused by an Act of Vandalism 485 Case Study 6.8 345-kV Phase-to-Ground (A-g) Fault Due to an Accident Along the Line Right-of-Way 489 Case Study 6.9 False Tripping of a 138-kV Current Differential Relaying System During an External Phase-to-Ground Fault 495 Case Study 6.10 Undesired Operation of a 13.8-kV Feeder Ground Relay During a Three-Phase Fault Due to an Extra CT Circuit Ground 502

CONTENTS xv Case Study 6.11 Correction of a System Model Error from Analysis of a Failure of a Post Insulator Associated with a 115-kV Disconnect Switch 512 Case Study 6.12 Location of a 345-kV Line Fault Protected by Electromechanical Distance Relays Using Information from a DFR Record 519 Case Study 6.13 Location of an Outdoor 13.8-kV Switchgear Fault at a Cogeneration Facility Using a DFR Fault Record from a Remote Substation 524 Case Study 6.14 Breakage (Failure) of a 345-kV Subconductor Bundle During a High-Resistance Tree Fault, Due to the Heavily Loaded Line Sagging to a Tree 529 Case Study 6.15 115-kV Phase-to-Phase Fault Caused by Failure of a Circuit Switcher 536 Case Study 6.16 Undesired Tripping of a 115-kV Feeder Due to a Setting Application Error in the Time Overcurrent Element for a Numerical Line Protection Relay 539 Case Study 6.17 Mitigation of Mutual Coupling Effects on the Reach of Ground Distance Relays Protecting Highand Extrahigh-Voltage Transmission Lines 544 7 CASE STUDIES RELATED TO CABLE TRANSMISSION FEEDER SYSTEM DISTURBANCES 571 Case Studies 572 Case Study 7.1 Optimum Design of Relaying Protection Zones Leads to Quick Identification of a Faulted 345-kV Submarine Cable Section 572 Case Study 7.2 Undesired Operation of a 138-kV Cable Feeder Differential Relay During the Commissioning Phase of a 500-MW Plant 578 Case Study 7.3 Phase-to-Ground Fault Caused by Failure of a 345-kV Cable Connection Between the Generator and the Switchyard, Accompanied by Mechanical Failure of One of the Cable Pot Head Phases 588 Case Study 7.4 Troubleshooting a 345-kV Phase-to-Ground Fault Using Relay Targets Only 595 Case Study 7.5 Failure of a 345-kV Cable Connection Between a 300-MW Generator and a 345-kV Switchyard, Causing a Phase-to-Ground Fault 603 Case Study 7.6 138-kV Cable Pot Head Failure Analysis Using Numerical Current Differential Relay Oscillography and Event Records 607

xvi CONTENTS 8 CASE STUDIES RELATED TO BREAKER FAILURE PROTECTION SYSTEM DISTURBANCES 615 8.1 Breaker Failure Protection Basics 616 Case Studies 626 Case Study 8.1 Tripping of a Combined-Cycle 150-MW Plant by Undesired Operation of a Solid-State Breaker Failure Relaying System 626 Case Study 8.2 115-kV Dual Breaker Failures Resulting in the Loss of a 1000-MW Plant and Associated Substations 634 Case Study 8.3 230-kV Substation Outage Due to Circuit Breaker Problems During the Clearing of a Close-in Phase-to-Ground Fault 640 Case Study 8.4 Failure of a 230-kV Circuit Breaker Leading to Isolation of a 1000-MW Plant and Associated Substations 646 Case Study 8.5 Generator CB Failure During Automatic Synchronization of the Circuit Breaker 654 Case Study 8.6 Circuit Breaker Re-strikes While Clearing Simultaneous Phase-to-Ground Faults on a 230-kV Double-Circuit Tower 660 Case Study 8.7 345-kV Capacitor Bank Breaker Fault Coupled with an Additional Failure of a Dual SF6 Pressure 345-kV Breaker During the Clearing of the Fault 664 Case Study 8.8 Oil Circuit Breaker Failure Following the Clearing of a Failed 230-kV Surge Arrester 671 Case Study 8.9 Detection of a Remote Circuit Breaker Problem from Analysis of a Local Oscillogram Monitoring Line Currents and Voltages 676 Case Study 8.10 Blackout of a 138-kV Load Area Due to a Primary Relay System Failure and the Lack of DC Control Power for the Secondary Relay System Circuit 678 Case Study 8.11 Installation of Two 345-kV Breakers in Series Within a Ring Substation Configuration to Mitigate the Loss of Critical Lines During Breaker Failure Events 682 Case Study 8.12 Design of Two 138-kV Circuit Breakers in Series to Fulfill the Need of Breaker Failure Protection 682 9 PROBLEMS 685 Index 715

PREFACE The fault recording equipment used in monitoring power systems evolved from a wet trace and light beams writing on special photo-sensitive paper or film oscillograms to digital, microprocessor-based technology. Some of the old records took days to develop, as in the case of the wet trace and recurring problems with sensitive papers. As a result, some key records were lost, making the analysis of power system disturbances extremely difficult. In addition, starting recording equipment was a hassle, causing unreliable oscillograph operations. A digital fault recorder (DFR) is considered an intelligent electronic device that can be accessed via communication links to send fault records automatically to remote operating centers and engineering offices immediately following a disturbance. This allowed a rapid analysis to make it possible to restore the system. Accurate root-mean-square measurements as well as a host of software packages can be executed to verify the system model and to assess the impact of disturbances on power system equipment. Analysis of power system disturbances is an important function that monitors the performance of a protection system. It can also provide a wealth of valuable information regarding correct behavior of the system. Understanding power system phenomena can be simplified, and adoption of safe operating limits and protective relaying practices can be enhanced. Review of DFR and numerical relay fault records for system operations can help to isolate incipient problems so that corrections can be implemented before the problems become serious. Understanding power system oscillations and system relaying response during a power swing condition can be enhanced, thus avoiding system blackouts. In addition, understanding power system engineering concepts and the use of symmetrical components in the analysis of power system faults can be enforced and enhanced through DFR analysis. A bulk power system is normally protected by two redundant relaying systems. The performance of these systems can be monitored through an analysis of system disturbances. Restoration of a power system requires correct analysis of the disturbance that caused the outage to confirm that it is safe to reenergize the system. Correct analysis can contribute to safe restoration without the fear of energizing faulty power system equipment. In addition, through proper system disturbance analysis confidence can be gained in the philosophy behind relaying application. To facilitate the reader s review process, the DFR records are accompanied by unique functional system diagrams that show the voltages and currents monitored, using designation labels that match the records. A section is devoted to documenting power system phenomena as they appear in actual case studies. This will provide xvii

xviii PREFACE engineers who have limited experience with such problems the necessary background to perform their own analyses of their systems. The book serves as a forum to document and present my 40+ years of experience in the area of power system disturbance analysis. Many colleagues from the American Electric Power Service Corp., the New York Power Authority, and several utilities have contributed to the book directly or indirectly, and I am grateful for their input. It has been my intention to simplify the topics presented and provide clear guidance as well as basic education to relay engineers. In this new format, the theory and basic fundamentals of relay applications are first briefly explained. This is then followed by real case studies involving system disturbances, to enforce these basics. The studies are based on actual occurrences collected through my years of involvement in the protection of utility systems. The real names of utility plants, substations, and lines have been replaced by generic labels. In the old vertical integration environment, training and education were essential to most utilities. In the highly competitive new environment, exchange of experience and technical information is hampered, as is passing useful experience to young engineers. At this point in the history of protective relaying, the fundamentals that have been handed down from generation to generation are in danger of becoming lost. This has given me the impetus to document my experience in a useful format that can benefit engineers, since little training is now available for engineers entering the protection and control field in the area of system disturbance analysis. In the book I present in detail how power system disturbance analysis is used as an important tool to judge the performance of protection systems. Actual DFR records, oscillograms, and numerical relay fault records are analyzed to demonstrate how to deduce the sequence of events. Topics such as the information needed for analysis, fault incident angle, and power system phenomena and their impact on relay system performance are covered. Power system phenomena derived from an analysis of system disturbances are described. In addition, case studies of actual system disturbances involving the performance of protection systems for generators, transformers, overhead transmission lines, cable feeders, and breaker failures are included. Several chapters are devoted to system disturbance analysis as a tool for optimizing the performance of relaying schemes. In addition, the book can serve as a tool for validating power system models and provides a wealth of technical information about the behavior of power systems. The book is intended primarily for engineers and technicians working in the areas of protection and control, power system operation, and electrical power system equipment. It is also intended for operators and support staff at energy control centers to enhance their technical background in the safe restoration of a power system following a disturbance. The book will provide engineers with a basic background in most power system phenomena and their impact on the behavior of protection systems. The book can also be used as a textbook for undergraduate and graduate students seeking to enhance their power backgrounds. A chapter is devoted to problems, to enhance understanding of the system disturbance analysis function. The book can thus provide an incentive to colleges to offer the system disturbance analysis topic in either an undergraduate or graduate course. MOHAMED A. IBRAHIM

1 POWER SYSTEM DISTURBANCE ANALYSIS FUNCTION An analysis of system disturbances provides a wealth of valuable information regarding power system phenomena and the behavior of protection systems. Experience can be enhanced and knowledge can be gained from the analysis function. This book is organized, first, to cover the analysis function and how it can be implemented. Then, in the following sections, phenomena related to system faults and the clearing process of faults from the power system are described. Power system phenomena derived from an analysis of system disturbances are stated. In addition, case studies of actual system disturbances involving the performance of protection systems for generators, transformers, overhead transmission lines, cable feeders, and breaker failures are provided. A section is devoted to problems that enhance an understanding of the system disturbance analysis function. Analysis of system disturbance is based on 60-Hz phenomena associated with power system faults. Therefore, sampling rates of digital fault recorders (DFRs) are designed to fulfill this requirement. High-frequency power system transient analysis requires special devices other than conventional DFRs and numerical relays, with unique requirements different from those of a traditional power system disturbance analysis function. Disturbance Analysis for Power Systems, First Edition. Mohamed A. Ibrahim. Ó 2012 Mohamed A. Ibrahim. Published 2012 by John Wiley & Sons, Inc. 1

2 POWER SYSTEM DISTURBANCE ANALYSIS FUNCTION To analyze the performance of protective relaying systems, high-speed digital fault and disturbance recording devices need to be employed properly. Equipment can be used for continuous monitoring of the behavior of relaying installed on a power system during the occurrence of either faults or power swing or switching operations. The equipment can be used to explain undesired operations and to assess system performance during correct operation. Analysis of fault records will help in adapting operating and protection practices and in assuring the reliability of a bulk power system. The analysis will also help to isolate problems and incipient failures. In addition, the strategic placement of DFR equipment should provide adequate coverage of the overall system response to any type of system fault or wide-area system disturbance. For this reason, DFR applications and implementation on a bulk power system are mandated by industry standards and regulations. A review of DFR records for every operation in a system will help to isolate incipient difficulties so that corrections can be provided before a serious problem develops and to provide basic useful information about the performance of the relaying system. A review of all fault records for disturbances on a system can enhance the reliability of a relay system. Systematic analysis of disturbances can play an important role in system blackout avoidance. When they occur during the early stage of analysis, flagging relay and system problems should be addressed before they precipitate into wider-area interruption and system blackouts. This can be accomplished by analyzing correct operations and finding the causes of incorrect operations. In addition, it can provide a better assessment of the validity of relay setting calculations, correct current transformer (CT) and voltage transformer (PT) ratios, and correct breaker operations. It can also enhance the system restoration process by providing fault types and locations and a better measure of power quality. The proposed NERC Reliability Standard PRC-002-02, Disturbance Monitoring and Reporting Requirements, is noted here as a document which ensures that regional reliability organizations establish requirements for the installation of disturbance-monitoring equipment and reporting of disturbance data to facilitate analyses of system events and verification of system models. 1.1 ANALYSIS FUNCTION OF POWER SYSTEM DISTURBANCES Analysis of power system disturbances can be summarized on the basis of the following primary functions: 1. The need to view fault data as soon as possible after a fault or disturbance occurs so as to restore the system safely. 2. The need to design the DFR with a reasonable pre-fault time (5 to 10 cycles) to capture incipient initiating conditions (e.g., surge arrester spillover). 3. The need to design the DFR with a long post-fault time, adjustable from 0 to 5 s, to be able to analyze backup protection clearing times (60 cycles or more) and

ANALYSIS FUNCTION OF POWER SYSTEM DISTURBANCES 3 limited power system swings (several seconds) following the occurrence of system disturbances. 4. The need to manipulate the data time base on the DFR record to analyze the effect of faults. 5. The need, finally, to manipulate the DFR data channels and view only those selected. Ideally, the analysis function should be carried out for all relay operations in a system. The normally cleared events can lead to the discovery of equipment problems and can also be used as a teaching example for power system behavior and phenomena. From the analysis function, monthly disturbance analysis reports can be prepared. In addition, other reports can be generated. The analysis function will focus primarily on providing answers to the following basic questions: 1. What happened? 2. Why did it happen? 3. What is going to be done about it? In essence, a sequence-of-events report, or time line, needs to be developed. Traditionally, a DFR monitors power system voltages and currents, whereas a sequence-of-events recorder (SER) monitors relay outputs, breaker and disconnect switch positions, alarms, relay targets, and relay communication channels. A DFR can integrate both functions by monitoring events and analog quantities. The following are some of the functions that analysis of DFR records, in conjunction with SER records, can provide: 1. Sequence of operation 2. Fault types 3. Clearing times 4. Reclosing times 5. Relay problems such as: (a) Failure to trip (b) Failure to target (c) Failure to reset (d) Delayed clearing 6. Communication problems such as: (a) False operation of blocking schemes during carrier transmission holes (b) Failure to operate for permissive overreaching transfer trip schemes during signal loss 7. Circuit breaker problems such as: (a) Contact arcing (b) Unequal pole closing

4 POWER SYSTEM DISTURBANCE ANALYSIS FUNCTION (c) Unequal pole opening (d) Re-strike (e) Reignition 8. Fault current and voltage magnitudes to confirm a short-circuit model 9. CT saturation 10. Asymmetrical current caused by dc (direct current) offset 11. Fault locations, currently provided by numerically based distance relaying, can also be provided by DFRs when sufficient analog signals per line are monitored 1.2 OBJECTIVE OF DFR DISTURBANCE ANALYSIS Data obtained from DFRs and numerical relaying can be used for continuous monitoring of the behavior of the relay system and assist in setting operating margins on critical control and protective apparatus in an electric power system during system disturbance events such as faults, power swings, and switching operations. Analysis of the data can have the dual role of explaining undesired operations and assessing system performance during correct operation. The primary objective of obtaining and analyzing DFR data is for the purpose of adapting operating and protection practices as well as control strategies to assure the security and dependability of the bulk power protection system. The secondary objective is for the purpose of helping to isolate problems and incipient failures. This requires a review of all DFR data for every operation, to detect and correct incipient troubles before they become a serious problem. The ability should exist for remote interrogation for data analysis and manipulation. Data need to be viewed as soon as possible after a fault or disturbance occurs. The data time base for the DFR record should be manipulated for analysis. The ability should exist to manipulate data channels and view only those of importance. This will ensure that other channels will not obscure vital data. It is a good idea to analyze all disturbances in a system, but this may require additional personnel who may not be available within the utility s environment. Indeed, it should be realized that the knowledge gained from analyzing mundane operations may prove to be very valuable. Following are some of the benefits that may be gained from an analysis of system disturbances: 1. Knowledge of the performance of the relaying system and associated inputs, outputs, communication system and circuit breakers 2. Root-mean-square (RMS) ground current calculations confirming the power system model 3. Development of statistics summarizing a fault

DETERMINATION OF POWER SYSTEM EQUIPMENT HEALTH 5 4. Optimization of the performance of the relaying system by optimizing the design process through analysis feedback 5. Identification of power system phenomena of interest to be used as teaching tools for engineers to enhance their basic technical backgrounds 6. Review of mundane operations that result in successful fault clearing to reveal valuable power system phenomena and correction of system design and modeling errors 1.3 DETERMINATION OF POWER SYSTEM EQUIPMENT HEALTH THROUGH SYSTEM DISTURBANCE ANALYSIS As mentioned earlier, an analysis of system disturbances can provide feedback regarding the integrity of power system equipment and associated protection systems. The following are examples of some of the feedback of analysis results that can be used to assess equipment health: 1. Detection of excessive capacitor bank outrush currents into close-in faults requires assessment of current transformer (CT) secondary-connected burdens to reduce overvoltage stress across CT secondary circuits. 2. Detection of circuit breaker (CB) re-striking current during the CB fault current interruption process requires CB inspection and examination for possible testing and maintenance. 3. Detection of unequal CB pole closing or opening requires inspection and examination for possible testing and maintenance of the circuit breaker. 4. Disappearance of third-harmonic current flow in generator neutrals requires assessment of generator neutrals for the possibility of either an open neutral or a stator ground fault near the neutral. 5. Determination of undesired relay operation and follow-up analysis can help in the detection of misapplications of relay settings. 6. Detection and follow-up analysis of undesired relay operation can lead to the discovery of certain hidden relay failures before the undesired operation can precipitate into a serious event that can stress the system. 7. Detection of mutual coupling phenomena can help in fine-tuning ground distance relay settings. 8. Detection of magnetic flux cancellation for CB tripping functions can help in identifying single failure criteria that can have a serious impact on clearing future occurrences of system faults. 9. Detection of excessive capacitative voltage transformer (CVT) transients upon the occurrence or clearing of close-in faults can lead to fine-tuning of the zone 1 distance relay setting reach.

6 POWER SYSTEM DISTURBANCE ANALYSIS FUNCTION 10. Thorough system disturbance analysis can lead to optimization of protective relaying dc schematics. 11. Thorough system disturbance analysis can lead to optimization of protective relay settings. 12. Thorough system disturbance analysis can lead to detection of surge arrester spillover that can lead to mitigation of the spill prior to failure. 13. Thorough system disturbance analysis can lead to detection of power system oscillation, which may require running stability studies to determine the need to add either out-of-step blocking or tripping relay schemes. 14. Thorough system disturbance analysis can lead to detection of CT saturation, which may require either reduction of secondary fault currents (by raising the CT ratio) or reduction of CT-connected burden. 15. Simulation and running of actual system faults, based on disturbance analysis, using computer-based test sets with the help of the COMTRADE fault current format can lead to a determination of failed relays and their associated auxiliary relays. 16. Analysis of multiphase faults caused by lightning strikes can lead to optimization of transmission tower footing resistance. 17. Determination of flashover at voltage peaks, leading to insulation failure as the main cause, can provide feedback to correct any insulation design deficiency. 1.4 DESCRIPTION OF DFR EQUIPMENT Figure 1.1 illustrates the basic subsystem blocks in a digital fault recorder. The analog input signals are first interfaced to a surge suppression package and sampling filters. The input current flows through a shunt and is converted to a voltage that is sampled, converted to digital form by an analog-to-digital (A/D) converter, and then read and processed by the microprocessor. Similarly, the input voltage is scaled down to a range compatible with the A/D range to be converted and then read and processed by the microprocessor. The A/D has to be checked periodically with sufficient accuracy and an acceptable A/D conversion resolution of a true 16 bits. Delta sigma A/D converters implemented on a commercial single-chip design, with built-in autocalibration capabilities and built-in linear-phase multistage digital decimation and filtering capability are used for some commercial DFRs to guarantee no aliasing in analog input-sampled signals. Binary inputs representing various functions within the substation are also sampled to give a time resolution of about 1 ms. The basic concepts of a DFR function of sampling and storing data whenever a trigger threshold is exceeded is executed inside the device memory by instruction steps within specific firmware. RAM memory is used for data and is normally checked on startup of the DFR device. ROM and PROM are used in the DFR algorithm and software analysis package and checked periodically by memory check sum routines. EPROM is used to store trigger and parameter settings. A programmable digital signal processing

INFORMATION REQUIRED FOR THE ANALYSIS OF SYSTEM DISTURBANCES 7 I Shunt V Surge protection & Filters Current & voltage inputs Contact inputs (DI) Digital input Signal conditioning A/D Sample / hold Sampling clock Microprocessor Power supply IRIG-B To GPS receiver HMI RAM ROM PROM EPROM Serial port Parallel port Communication Remote Locations Fig. 1.1 Subsystems of a DFR device. microprocessor is used to perform serial parallel conversions and extended-precision adder functions, triggering of recording via various algorithms, and trigger timing management. The DFR-captured data can be retrieved from a remote location via an acquisition computer called the master station. The DFR system should be timesynchronized using an IRIG-B signal from global positioning satellite (GPS) receivers. DFR equipment offers normal communication capability to allow for remote retrieval of fault and event records, making for immediate disturbance analysis and reducing the time and cost needed to perform the analysis task. 1.5 INFORMATION REQUIRED FOR THE ANALYSIS OF SYSTEM DISTURBANCES The sequence of events can be derived from an analysis of the fault information that may be available from several devices. Presently, the problem is that too many data are available from every intelligent electronic device (IED) and the challenge is for relay and operating engineers to select the most vital data, which need to be analyzed quickly to restore the affected system safely. A sequence-of-events report may be developed using some of the following data: 1. Digital fault recorder records and/or oscillograms (if applicable) 2. Sequence-of-event recorder records

8 POWER SYSTEM DISTURBANCE ANALYSIS FUNCTION 3. Relay targets 4. Numerically based protection oscillograph fault records (if applicable) 5. Phasor measurement records 6. System operation logs 7. Event story as created by field personnel 8. SCADA record, indicating system configurations and loading 9. PC-based short-circuit study simulations 10. As-built one-line, ac three-line, elementary, wiring, and logic diagrams 11. Operating procedures 12. Computer logs and customer information 13. Description of system clearances in the event of an operating or technician error 14. Strip/chart recording or smart IED meters of power system quantities (active power, reactive power, frequency, voltage, and current) 1.6 SIGNALS TO BE MONITORED BY A FAULT RECORDER 1.6.1 Analog Signals A DFR will monitor voltages and currents as well as digital inputs from the electrical power system. Channel assignments to the DFR should consider monitoring sufficient information to implement the fault location option. This requires the monitoring of three phase-neutral voltages and three phase currents with an option to either monitor or calculate the neutral current (I n ) for each transmission line. In addition, the DFR should monitor all neutral currents and ground sources at the substation to be able to validate the short-circuit model for ground faults. Validation of a short-circuit model for phase faults is difficult to accomplish, due to the effect of loading, which is normally not factored in a steady-state quasi-short-circuit study simulation. The analog channels are normally configurable as voltage or current inputs. The phase-to-neutral voltage inputs may be scaled for about 66.4 V, with a range of 0 to 250 V RMS, allowing a margin of more than 2 pu (per unit) overvoltage. Current inputs may be scaled for 5 A RMS (nominal load current) and at least 100 A full-scale input using calibrated shunts. The thermal duty can be rated at least 10 A RMS continuous and at least 200 A RMS short time for 2s. Monitoring a generator dc field current can provide valuable educational information about negative-sequence double-frequency-induced rotor current during unbalanced system faults. In addition, monitoring a generator dc field will reveal the 60-Hz induced rotor current during inadvertent energization of generator incidents. Both phenomena are illustrated herein through applicable generator case studies. Dedicated sensors with over, under, and rate-of-change value settings were used for traditional (conventional) oscillographs. DFRs can also be programmed for

SIGNALS TO BE MONITORED BY A FAULT RECORDER 9 each analog channel for over, under, or rate-of-change settings. Additional sensors may include positive-sequence current or voltage, negative-sequence current or voltage, zero-sequence current or voltage, frequency transducers rate of change of impedance during a power system swing (long-term rate of change), and total harmonic distortion. Following is a list of typical analog channels monitored at the substation level:. Phase-to-neutral voltages. Line phase and neutral currents. Transformer neutral currents. Transformer tertiary currents. Transformer polarizing currents (sum of more than one current). Capacitor currents (phase and neutral). Shunt reactor currents. Transformer high- and low-side currents. Zero-sequence voltages. Bus voltages. Generator neutral voltages. Generator fields. Generator currents. Generator phase-to-neutral voltages Monitoring of tertiary (3I 0 ) current by a DFR may help in the classification of ground faults. The CTs for all the phases are paralleled to collect ground current (3I 0 ) and filter out any loading currents (the sum of balanced positive-sequence currents ¼ 0). For breaker-and-one-half substation configuration, monitoring of the middle breaker ground current can provide valuable information for circuit breaker maintenance by showing the last breaker of the two that will interrupt the fault current. In addition, determination of which of the two line breakers is exhibiting a re-strike during the faultclearing process can be accomplished. 1.6.2 Event (Digital or Binary) Inputs and Outputs Most DFR systems provide means for event recording. This may be status change (closing or opening) of an auxiliary contact associated with a circuit breaker or a disconnect switch operation or the presence of voltage at a control circuit node, which would indicate that a certain control logic function was performed. Examples of events are positions for circuit breakers; disconnect switches, dc presence for control circuits, relays, auxiliary relays, lockout relays, and protection communication signals. Event recording can also be performed by dedicated SERs in the form of stand-alone packages or as part of other systems, such as remote terminals for SCADA systems. Most SER systems are designed with a typical 1-ms resolution time.

10 POWER SYSTEM DISTURBANCE ANALYSIS FUNCTION 1.7 DFR TRIGGER SETTINGS OF MONITORED VOLTAGES AND CURRENTS In older oscillograph equipment, recording was generally begun using dedicated start sensors to capture fault records. Delta tertiary zero-sequence currents and transformer neutral currents were commonly used to sense ground faults. Undervoltage sensors were also used at key voltage points within the substation, together with an operation limiter, to sense phase faults. Dedicated negative-sequence sensors were also used to trigger the device for unbalanced faults. The present state-of-the-art DFR is designed with trigger algorithms that are capable of detecting over, under, rate-of-change, and swing conditions for each analog input channel. The trigger algorithm provides concurrent user selectivity for step change, ramp change, and oscillatory conditions. The DFR is normally triggered to capture a record by all analog channels and selected binary inputs. The DFR monitors for line faults three phase-to-neutral voltages and three phase and neutral currents for each line connected at the substation. Phase undervoltage and phase overcurrents will trigger the DFR for phase line faults, and neutral currents will trigger for ground line faults. One analog trigger is sufficient to capture a DFR record. In addition, triggering can be initiated using positive-, negative-, and zerosequence symmetrical components as a supplement for shunt faults and as a main trigger for series imbalance, such as open phase. A frequency computation from a bus voltage can also trigger a frequency deviation. Total harmonic distortion and individual harmonic distortion for a specific frequency can also be programmed to trigger a DFR to provide an analysis of power quality. Impedance can also be calculated and used to trigger a DFR. Power swing amplitude for voltage, current, and active and reactive power, as well as oscillation frequency and rate of change of impedance, can also be used to trigger a DFR. In addition, selected digital inputs can be used to capture a record: for example, emergency shutdown lockout relays, which can be energized by many abnormal conditions at a generating plant. Manual triggering is also provided to test the data capture and output function of a DFR. The manual trigger may be hardwired or software based, with an option for remote acquisition from a master station location. The DFR can also be configured to have a very slow scan to capture long-term events such as power system oscillations or out-ofstep conditions. Each trigger function is user programmable with an individual dualmode limiter function. This function prevents excessive recording both in case a trigger condition persists for an extended period of time and in case a chattering trigger should occur. The operation limiter feature will restrict data recording to a selectable length in the event of a continuous long-term trigger condition. An example is the use of undervoltage to trigger the capture of a record for phase faults on a system. Since all analog-monitored channels will be used as triggers, this voltage may be associated with a transmission line. When the line is removed from service during a scheduled outage, the undervoltage sensor will trigger the DFR to capture a record. However, a mean must be established to limit the length of the record since triggering will continue as long as the line is out of service. It should be noted that if phase overcurrent is used to trigger a DFR for faults, the operation limiter feature is not required.